Oil field operators demand access to a great quantity of information regarding the parameters and conditions encountered downhole. Such information includes characteristics of the earth formations traversed by the borehole and/or data relating to the size and configuration of the borehole itself. The measured parameters are usually recorded and displayed in the form of a log, i.e., a graph showing the measured parameter as a function of tool position or depth. The collection of information relating to conditions downhole is commonly referred to as “logging”.
Many types of downhole tools exist. One available type of downhole tool is a nuclear magnetic resonance (NMR) logging tool. NMR tools operate by using an imposed static magnetic field, B0, to preferentially align certain nuclei and thereby produce a bulk magnetization. After a change in the static field, the nuclei converge upon their equilibrium alignment with a characteristic exponential relaxation time constant known as the “spin-lattice” or “longitudinal” relaxation time T1. Another relaxation time constant that can be measured is the “spin-spin” or “transverse” relaxation time T2. The tool applies a radio frequency electromagnetic pulse whose magnetic component, B1, is perpendicular to the static field B0. This pulse tips the nuclei's magnetic orientation into the transverse (perpendicular) plane and, once the pulse ends, causes them to precess (“spin”) in the transverse plane as they realign themselves with the static field. The T2 relaxation time constant represents how quickly the transverse plane magnetization disperses through de-phasing and magnitude loss. The precessing nuclei generate a detectable radio frequency signal that can be used to measure statistical distributions of T1 and T2, from which other formation properties such as porosity, permeability, and hydrocarbon saturation can be determined. To enhance the measurement accuracy of the relaxation times, the tool can provide a sequence of radio frequency pulses (such as the well-known Carr-Purcell-Meiboom-Gill “CPMG” pulse sequence) to invert the spin phase and cause the dispersed transverse plane magnetization to gradually refocus into phase, thereby inducing a series of “spin echo” signals. If an NMR tool collects measurements as a function of three spatial dimensions, it is usually called a magnetic resonance imaging (MRI) tool.
Another available downhole tool is a formation tester. Formation testers isolate a portion of the borehole wall, either with an isolation pad or a configuration of one or more inflatable packers. The isolated portion of the borehole wall is optionally “cleaned” and then subjected to a pressure test. The pressure test may include a suction phase in which some volume in front of the isolated borehole wall region is first evacuated and then allowed to fill with fluid from the formation. The fluid sample, together with the pressure-versus-time profile, reveals a great deal of information about formation permeability, fluid type, fluid quality, formation pressure, formation temperature, bubblepoint, and (for multiple measurements) the formation pressure gradient. The pressure test may additionally or alternatively include an injection phase in which the volume in front of the isolated borehole wall region is pressurized to inject a test fluid into the formation. The injection test can be conducted in a variety of ways. For example, the volume may be pressurized to a given pressure and then allowed to equilibrate. Alternatively, the tool may continually increase the pressure until the formation fractures and a certain quantity of fluid has been injected. As yet another option, the tool may attempt to inject a given amount of fluid within a given amount of time. In any event, the pressure-versus-time profile is monitored to determine properties such as formation permeability, fracture initiation pressure, and formation pressure.
Despite the availability of the tools described above and many others, there yet remains a number of formation properties that cannot be measured in situ by any existing tool. For example, the authors are unaware of any tools that can measure the manner in which formation fractures are initiated and propagated, or which can measure the movement of fluids within a newly formed fracture to provide a real-time indication of fracture volume and orientation.
It should be understood that the drawings and detailed description thereto do not limit the disclosure to the particular illustrated embodiments, but on the contrary, the illustrated embodiments provide a foundation for understanding all modifications, equivalents and alternatives falling within the scope of the disclosure and appended claims.